Systems and Methods for an Expandable Packer

ABSTRACT

The present disclosure relates to a downhole packer assembly that includes an inner packer and a drain coupled to the inner packer. The drain includes a sample inlet, a guard inlet, and a seal disposed between the sample inlet and the guard inlet. The seal is configured to move into a space between the sample inlet and the guard inlet based on hydrostatic pressure

BACKGROUND OF THE DISCLOSURE

Wellbores or boreholes may be drilled to, for example, locate andproduce hydrocarbons. During a drilling operation, it may be desirableto evaluate and/or measure properties of encountered formations andformation fluids. In some cases, a drillstring is removed and a wirelinetool deployed into the borehole to test, evaluate and/or sample theformations and/or formation fluid(s). In other cases, the drillstringmay be provided with devices to test and/or sample the surroundingformations and/or formation fluid(s) without having to remove thedrillstring from the borehole.

Formation evaluation may involve drawing fluid from the formation into adownhole tool for testing and/or sampling. Various devices, such asprobes and/or packers, may be extended from the downhole tool to isolatea region of the wellbore wall, and thereby establish fluid communicationwith the subterranean formation surrounding the wellbore. Fluid may thenbe drawn into the downhole tool using the probe and/or packer. Withinthe downhole tool, the fluid may be directed to one or more fluidanalyzers and sensors that may be employed to detect properties of thefluid while the downhole tool is stationary within the wellbore.

SUMMARY

The present disclosure relates to a downhole packer assembly thatincludes an inner packer and a drain coupled to the inner packer. Thedrain includes a sample inlet, a guard inlet, and a seal disposedbetween the sample inlet and the guard inlet. The seal is configured tomove into a space between the sample inlet and the guard inlet based onhydrostatic pressure.

The present disclosure also relates to a method including providing apacker assembly having an inner packer and a drain coupled to the innerpacker. The drain includes a sample inlet, a guard inlet, and a sealdisposed between the sample inlet and the guard inlet. The method alsoincludes positioning the packer assembly in a wellbore, inflating theinner packer until the drain is adjacent a wall of the wellbore, movingthe seal into a space between the sample inlet and the guard inlet basedon hydrostatic pressure, collecting a first formation fluid through thesample inlet, and collecting a second formation fluid through the guardinlet. The seal blocks mixing of the first and second formation fluidsin the space.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 is a schematic front elevation view of an embodiment of a wellsystem having a packer assembly through which formation fluids may becollected, according to aspects of the present disclosure;

FIG. 2 is an orthogonal view of one example of the packer assemblyillustrated in FIG. 1, according to an embodiment of the presentdisclosure;

FIG. 3 is an orthogonal view of one example of an outer layer that canbe used with the packer assembly, according to an embodiment of thepresent disclosure;

FIG. 4 is a view similar to that of FIG. 3 but showing internalcomponents of the outer layer, according to an embodiment of the presentdisclosure;

FIG. 5 is a front view of a drain of a packer assembly according to anembodiment of the present disclosure;

FIG. 6 is a cross-sectional view of a drain of a packer assembly with aninflatable seal according to an embodiment of the present disclosure;

FIG. 7 is a cross-sectional view of a drain of a packer assembly with aninflatable seal in a sealing position according to an embodiment of thepresent disclosure;

FIG. 8 is a cross-sectional view of a portion of a drain of a packerassembly with an inflatable seal according to an embodiment of thepresent disclosure;

FIG. 9 is a cross-sectional view of an inflatable four-layer sealaccording to an embodiment of the present disclosure;

FIG. 10 is a cross-sectional view of an inflatable two-layer sealaccording to an embodiment of the present disclosure;

FIG. 11 is a cross-sectional view of an external layer of an inflatableseal according to an embodiment of the present disclosure;

FIG. 12 is a cross-sectional view of a drain of a packer assembly with apiston seal according to an embodiment of the present disclosure; and

FIG. 13 is a cross-sectional view of a drain of a packer assembly withtwo inflatable seals in a sealing position according to an embodiment ofthe present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various embodiments and/or configurations discussed.Moreover, the formation of a first feature over or on a second featurein the description that follows may include embodiments in which thefirst and second features are formed in direct contact, and may alsoinclude embodiments in which additional features may be formedinterposing the first and second features, such that the first andsecond features may not be in direct contact.

The present disclosure relates to systems and methods for an expandablepacker, such as an expandable packer assembly used as part of a downholetool disposed in a wellbore. In certain embodiments, formation fluidsamples are collected through an outer layer of the packer assembly andconveyed to a desired collection location. In addition, the packerassembly may include an expandable sealing element that enables thepacker assembly to better support the formation in a produced zone atwhich formation fluids are collected. In certain embodiments, the packerassembly expands across an expansion zone, and formation fluids can becollected from the middle of the expansion zone, i.e. between axial endsof the outer sealing layer. The formation fluid collected is directedalong flowlines, e.g. along flow tubes, having sufficient inner diameterto allow operations in a variety of environments. Formation fluid can becollected through one or more drains. For example, separate drains canbe disposed along the circumference of the packer assembly to establishcollection zones. Each drain may include a sampling zone and a guardzone that enables focused sampling. Separate flowlines can be connectedto the sampling and guard zones to enable the collection of uniqueformation fluid samples.

In certain embodiments, the packer assembly includes several componentsor layers, such as an outer skin and an inner packer disposed within theouter skin such that inflation of the inner packer causes the outer skinto expand. In addition, a drain may be coupled to the outer skin and thedrain may include a sample inlet, a guard inlet, and a seal disposedbetween the sample inlet and the guard inlet. The seal may be configuredto move into a space between the sample inlet and the guard inlet basedon hydrostatic pressure (i.e., the borehole pressure). During operationof the packer assembly, the sample inlet may be used to collect a firstformation fluid (e.g., uncontaminated formation fluid) and the guardinlet may be used to collect a second formation fluid (e.g.,contaminated formation fluid). After the seal has moved into the spacebetween the sample and guard inlets, the seal may block mixing of thefirst and second formation fluids in the space. Thus, embodiments of theseal help the packer assembly to collect relatively uncontaminatedformation fluid that is representative of the fluid in the formation. Inaddition, the disclosed embodiments of the seal may provide improvedsealing performance as the hydrostatic pressure increases. Further,embodiments of the seal may provide improved sealing when the walls ofthe wellbore possess irregularities.

Referring generally to FIG. 1, one embodiment of a well system 20 isillustrated as deployed in a wellbore 22. The well system 20 includes aconveyance 24 employed to deliver at least one packer assembly 26downhole. In many applications, the packer assembly 26 is deployed byconveyance 24 in the form of a wireline, but conveyance 24 may haveother forms, including tubing strings, for other applications. In theillustrated embodiment, the packer assembly 26 is used to collectformation fluids from a surrounding formation 28. The packer assembly 26is selectively expanded in a radially outward direction to seal acrossan expansion zone 30 with a surrounding wellbore wall 32, such as asurrounding casing or open wellbore wall. When the packer assembly 26 isexpanded to seal against wellbore wall 32, formation fluids can beflowed into the packer assembly 26, as indicated by arrows 34. Theformation fluids are then directed to a flowline, as represented byarrows 35, and produced to a collection location, such as a location ata well site surface 36. As described in detail below, the packerassembly 26 may include a seal configured to move into a space between asample inlet and a guard inlet based on hydrostatic pressure.

Referring generally to FIG. 2, one embodiment of the packer assembly 26is illustrated, which may have an axial axis or direction 37, a radialaxis or direction 38, and a circumferential axis or direction 39. Inthis embodiment, packer assembly 26 includes an outer layer 40 (e.g.,outer skin) that is expandable in the wellbore 22 to form a seal withsurrounding wellbore wall 32 across expansion zone 30. The packerassembly 26 further includes an inner, inflatable bladder 42 disposedwithin an interior of outer layer 40. In one example, the inner bladder42 (e.g., inner packer) is selectively expanded by fluid delivered viaan inner mandrel 44. Furthermore, packer assembly 26 includes a pair ofmechanical fittings 46 that are mounted around inner mandrel 44 andengaged with axial ends 48 of outer layer 40.

With additional reference to FIG. 3, outer layer 40 may include one ormore windows or drains 50 through which formation fluid is collectedwhen outer layer 40 is expanded against surrounding wellbore wall 32.Drains 50 may be embedded radially into a sealing element 52 of outerlayer 40. By way of example, sealing element 52 may be cylindrical andformed of an elastomeric material selected for hydrocarbon basedapplications, such as nitrile rubber (NBR), hydrogenated nitrilebutadiene rubber (HNBR), and fluorocarbon rubber (FKM). A plurality oftubular members, tubes, or flowlines 54 may be operatively coupled withdrains 50 for directing the collected formation fluid in an axial 37direction to one or both of the mechanical fittings 46. As furtherillustrated in FIG. 4, flowlines 54 may be aligned generally parallelwith a packer axis 56 that extends through the axial ends of outer layer40.

FIG. 5 is a front view of an embodiment of the drain 50 of the packerassembly 26. The illustrated embodiment includes a sampling zone 70, aseal 72 surrounding the sampling zone, and a guard zone 74 surroundingthe seal 72. As shown in FIG. 5, the seal 72 divides the drain 50 intothe sampling and guard zones 70 and 74. The embodiment of the drain 50may be used for guarded or focused sampling. Fluid collected in thesampling zone 70 is relatively less contaminated by filtrate than fluidcollected in the guard zone 74. Thus, focused sampling may be used toachieve more representative samples of formation fluid in less time thannon-focused sampling. As shown in FIG. 5, the drain 50 may have anelongated shape. In other embodiments, the drain 50 may have othershapes, such as, but not limited to, a circular shape, an oval shape, anelliptical shape, a square shape, a rectangular shape, or a polygonalshape. In certain embodiments, the seal 72 is configured with a shapesubstantially matching that of the drain. For example, the seal 72 maybe configured as an oval or circular ring.

FIG. 6 is a cross-sectional view of an embodiment of the drain 50 of thepacker assembly 26 taken along line 6-6 of FIG. 5. As shown in FIG. 6,the seal 72 is disposed within the outer layer 40 (e.g., outer skin). Inthe illustrated embodiment, the seal 72 is configured as an inflatableseal. Specifically, the inflatable seal 72 includes an interior 90surrounded by one or more layers 92. As described in detail below, afluid at hydrostatic pressure may be introduced into the interior 90 toinflate the inflatable seal 72. The inflatable seal 72 shown in FIG. 6is in an un-inflated or deflated state. In addition, the inflatable seal72 is at least partially disposed in a seal groove 94 that at leastpartially contains or holds the seal 72. In the illustrated embodiment,the drain 50 includes a sampling inlet 96 configured to collect fluidfrom the sampling zone 70 and a guard inlet 98 configured to collectfluid from the guard zone 74. The sampling and guard inlets 96 and 98may be coupled to separate flowlines 54 (not shown) to convey fluidsthrough the packer assembly 26. As described in detail below, when theinflatable seal 72 is inflated, the inflatable seal 72 moves into aspace 100 between the sampling and guard inlets 96 and 98 based on thehydrostatic pressure of the fluid in the interior 90.

FIG. 7 is a cross-sectional view of an embodiment of the drain 50 of thepacker assembly 26 taken along line 6-6 of FIG. 5. The inflatable seal72 shown in FIG. 7 is in an inflated state. Specifically, theintroduction of fluid at hydrostatic pressure into the interior 90 ofthe inflatable seal 72 has caused the inflatable seal 72 to inflate asindicated by arrows 110 until the one or more layers 92 of theinflatable seal 72 have contacted the formation 28 or wellbore wall 32(e.g., casing or open wellbore wall). In other words, the inflatableseal 72 shown in FIG. 7 has moved into the space 100 between thesampling and guard inlets 96 and 98 based on the hydrostatic pressure ofthe fluid in the interior 90. More specifically, the inflatable seal 72inflates because the hydrostatic pressure within the interior 90 of theinflatable seal 72 is greater than a pressure in a drawdown zone 112(e.g., sampling and guard zones 70 and 74). Drawdown may refer to theuse of a pump or piston in the packer assembly 26 to decrease thepressure in the drawdown zone 112 adjacent the drain 50 to cause fluidfrom the formation 28 to enter the packer assembly 26. When the pressurein the drawdown zone 112 is less than a formation pressure, thedifferential pressure may cause fluid to flow out from the formation 28and into the drawdown zone 112. The greater the difference between thehydrostatic pressure within the interior 90 and the drawdown pressure,the greater the inflation the inflatable seal 72 undergoes. As shown inFIG. 7, the inflatable seal 72 blocks fluids in the sampling and guardzones 70 and 74 from mixing with one another. Accordingly, theinflatable seal 72 enables the sampling inlet 96 to collect fluid fromthe sampling zone 70 that is separate from the fluid the guard inlet 98collects from the guard zone 74. Thus, the inflatable seal 72 helpsimprove the focused sampling performance of the drain 50.

FIG. 8 is a cross-sectional view of a portion of an embodiment of thedrain 50 with the inflatable seal 72. In the illustrated embodiment, theinflatable seal 72 includes an opening 130 through which the fluid atthe hydrostatic pressure may enter or leave. The opening 130 may befluidly coupled to a source 132 of the fluid at the hydrostaticpressure. As shown, the source 132 may be contained within a hydrostaticfluid flowline 134 formed within the drain 50 or packer assembly 26. Thehydrostatic fluid flowline 134 may be supplied with borehole fluid orother fluid within the packer assembly 26 that is at the hydrostaticpressure. In certain embodiments, the hydrostatic fluid flowline 134 mayinclude a valve 136 used to control or adjust the flowrate of the fluidat the hydrostatic pressure. For example, the valve 136 may be openedwhen sealing of the sampling and guard zones 70 and 74 is desired andclosed when sealing is no longer desired. In addition, the valve 136 maybe partially closed to reduce the amount or flowrate of fluid at thehydrostatic pressure that enters the interior 90, thereby reducing theinflation of the inflatable seal 72. Similarly, the valve 136 may beopened to increase the amount or flowrate of fluid at the hydrostaticpressure that enters the interior 90, thereby increasing the inflationof the inflatable seal 72.

In certain embodiments, the valve 136 shown in FIG. 8 may be coupled toan actuator 138. For example, the conveyance 24 may include a processor140 of a control/monitoring system 142. In the context of the presentdisclosure, the term “processor” refers to any number of processorcomponents. The processor 140 may include a single processor disposedonboard the conveyance 24. In other implementations, at least a portionof the processor 140 (e.g., where multiple processors collectivelyoperate as the processor 140) may be located within the well system 20of FIG. 1 and/or other surface equipment components. The processor 140may also or instead be or include one or more processors located withinthe conveyance 24 and connected to one or more processors located indrilling and/or other equipment disposed at the wellsite surface.Moreover, various combinations of processors may be considered part ofthe processor 140. Similar terminology is applied with respect to thecontrol/monitoring system 142, as well as a memory 144 of thecontrol/monitoring system 142, meaning that the control/monitoringsystem 142 may include various processors communicatively coupled toeach other and/or various memories at various locations.

FIG. 9 is a cross-sectional view of an embodiment of the inflatable seal72 with four layers. As shown in FIG. 9, the inflatable seal 72 includesa first innermost sealing layer 160 that surrounds the interior 90. Incertain embodiments, the first innermost sealing layer 160 may be madefrom an elastomeric material, such as, but not limited to, rubber, whichmay help block the fluid in the interior 90 from reaching or contactingother layers of the inflatable seal 72. Next, a second anti-extrusionlayer 162 surrounds the first innermost sealing layer 160. In certainembodiments, the second anti-extrusion layer 162 may be made from one ormore fibers, which may help block extrusion of the elastomeric materialof the first innermost sealing layer 160 during inflation of theinflatable seal 72. Next, a third mechanical layer 164 surrounds thesecond anti-extrusion layer 162. In certain embodiments, the thirdmechanical layer 164 may be made from one or more cables, which may alsohelp reduce stress on the second anti-extrusion layer 162 duringinflation of the inflatable seal 72. Finally, a fourth external skinlayer 166 surrounds the third mechanical layer 164. In certainembodiments, the fourth external skin layer 166 may be made from anelastomeric material, such as, but not limited to, rubber, which mayprovide an effective sealing surface with the formation 28. Thefour-layer structure of the illustrated embodiment of the inflatableseal 72 may provide increased durability compared to otherconfigurations of the inflatable seal 72. Specifically, the four-layerstructure may provide increased resistance to failure or leakage at highpressures and/or high temperatures, such as those encountered in thewellbore 22.

FIG. 10 is a cross-sectional view of an embodiment of the inflatableseal 72 with three layers. As shown in FIG. 10, the inflatable seal 72includes an inner mechanical layer 180 that surrounds the interior 90.In certain embodiments, the inner mechanical layer 180 may be made froma flexible material, which may help block the fluid from escaping theinterior 90. In certain embodiments, the inner mechanical layer 180includes an inner opening 182 that enables the inner mechanical layer180 to expand radially 37. Next, an outer mechanical layer 184 surroundsthe inner mechanical layer 180. In certain embodiments, the outermechanical layer 184 may be made from a flexible material, which mayhelp block the transfer of fluid to or from the interior 90. In certainembodiments, the outer mechanical layer 184 includes an outer opening186 that enables the outer mechanical layer 184 to expand radially 37.As shown in FIG. 10, the outer opening 186 may be disposed opposite fromthe inner opening 182 to help block fluid from escaping the interior 90.In certain embodiments, the inner and outer mechanical layers 180 and184 may be coupled to one another via an adhesive or other mechanicalbonding technique, which may help block fluid from flowing from theinterior 90, through the inner opening 182, and along the interfacebetween the inner and outer mechanical layers 180 and 184. Alternativelyor additionally, two or more O-rings 188 may be disposed between theinner and outer mechanical layers 180 and 184 to form a seal blockingfluid from escaping the interior 90. Next, an external skin layer 190surrounds the outer mechanical layer 184. In certain embodiments, theexternal skin layer 190 may be made from an elastomeric material, suchas, but not limited to, rubber, which may provide an effective sealingsurface with the formation 28 or wellbore wall 32 (e.g., casing or openwellbore wall). The external skin layer 190 may include one or moreopenings 192 to help improve the sealing provided by the inflatable seal72. For example, with two openings 192, the external skin layer 190includes an upper portion 194 that contacts the formation 28 or wellborewall 32 (e.g., casing or open wellbore wall) and a lower portion 196that contacts the seal groove 94. Such a split or divided design for theexternal skin layer 190 may provide additional operational flexibility.For example, the upper portion 194 may be made from a more durablematerial selected for repeated contact against the formation 28 orwellbore wall 32 (e.g., casing or open wellbore wall) compared to thematerial selected for the lower portion 196. Further, the materialselected for the external skin layer 190 may be chosen based on theexternal skin layer 190 undergoing compression work and not acombination of compression and tension. Such materials selected forcompression work may be less costly, more readily available, and/or moredurable than other materials.

FIG. 11 is a cross-sectional view of an embodiment of the external skinlayer 190 of the inflatable seal 72 of FIG. 10. As shown in FIG. 11, theexternal skin layer 190 may have a shape that improves sealing of theinflatable seal 72 against the formation 28 or wellbore wall 32 (e.g.,casing or open wellbore wall). For example, the external skin layer 190may have a relatively flat surface 200 that contacts the formation 28 orwellbore wall 32 (e.g., casing or open wellbore wall). Other suitableshapes may be used for the external skin layer 190 depending on theparticular conditions, composition, or irregularities of the wellbore22. Such shapes may be possible because the external skin layer 190works in compression and not in both compression and tension in certainembodiments. As shown in FIG. 11, the external skin layer 190 may beseparated into the upper and lower portions 194 and 196 by the opening192.

FIG. 12 is a cross-sectional view of an embodiment of the drain 50 ofthe packer assembly 26 taken along line 6-6 of FIG. 5. As shown in FIG.12, the seal 72 is configured as a piston seal. Specifically, the pistonseal 72 includes a piston 210 disposed in a piston chamber 212, which isfluidly coupled to the hydrostatic fluid flowline 134. A sealing layer214 may be coupled to an external surface 216 of the piston 210 and thesealing layer 214 may be configured to seal against the formation 28 orwellbore wall 32 (e.g., casing or open wellbore wall) as shown in FIG.12. In certain embodiments, the sealing layer 214 may be made from anelastomeric material, such as, but not limited to, rubber, which mayprovide an effective sealing surface with the formation 28 or wellborewall 32 (e.g., casing or open wellbore wall). In addition, a thicknessof the piston 210 may be reduced to help the piston 210 and sealinglayer 214 to better comply with or adapt to irregularities in theformation 28 or wellbore wall 32 (e.g., casing or open wellbore wall).

When the embodiment of the piston seal 72 shown in FIG. 12 is inoperation, the fluid at hydrostatic pressure may push the piston 210 asindicated by arrows 218, causing the sealing layer 214 to move into thespace 100 between the sampling and guard inlets 96 and 98 based on thehydrostatic pressure of the fluid in the piston chamber 212. Morespecifically, the piston seal 72 operates because the hydrostaticpressure within the piston chamber 212 is greater than the pressure inthe drawdown zone 112 (e.g., sampling and guard zones 70 and 74). Thegreater the difference between the hydrostatic pressure within thepiston chamber 212 and the drawdown pressure, the greater the force thesealing layer 214 exerts upon the wellbore 28 or wellbore wall 32 (e.g.,casing or open wellbore wall). As shown in FIG. 12, the sealing layer214 blocks fluids in the sampling and guard zones 70 and 74 from mixingwith one another. Accordingly, the piston seal 72 enables the samplinginlet 96 to collect fluid from the sampling zone 70 that is separatefrom the fluid the guard inlet 98 collects from the guard zone 74. Thus,the piston seal 72 helps improve the focused sampling performance of thedrain 50. In certain embodiments, a piston O-ring 220 may be used tohelp block the fluid at hydrostatic pressure in the piston chamber 212from entering the drawdown zone 112 during operation of the piston seal72. In further embodiments, the valve 136 may be used to control oradjust the flowrate of the fluid at the hydrostatic pressure in asimilar manner as discussed above with respect to the embodiment of theinflatable seal 72 shown in FIG. 8. In still further embodiments, thepiston seal 72 may include a stop configured to block the piston 210from moving completely out of the piston chamber 212. For example, thepiston chamber 212 may include a shoulder to block movement of thepiston 210 out of the piston chamber 212.

FIG. 13 is a cross-sectional view of an embodiment of the drain 50 withthe inflatable seal 72 separating the sampling and guard zones 70 and74. In addition, the drain includes a second inflatable seal 230surrounding the guard zone 74. Thus, the second inflatable seal 230blocks fluid present in the wellbore 22 from entering the guard zone 74,thereby helping the drain 50 to collect representative samples of fluidfrom the formation 28 and improving the focused sampling performance ofthe drain 50. The second inflatable seal 230 may operate in a similarmanner to the inflatable seal 72. Specifically, the introduction offluid at hydrostatic pressure into the interior 90 of the secondinflatable seal 230 causes the second inflatable seal 230 to inflate asindicated by arrows 110 until one or more layers 92 of the secondinflatable seal 230 contact the formation 28 or wellbore wall 32 (e.g.,casing or open wellbore wall). The greater the difference between thehydrostatic pressure within the interior 90 and the drawdown pressure,the greater the inflation the second inflatable seal 230 undergoes. Incertain embodiments, use of the second inflatable seal 230 may enablethe outer layer 40 of the packer assembly 26 to be omitted, therebysimplifying the construction and reducing the cost of the packerassembly 26. In further embodiments, the second inflatable seal 230 maybe used together with the outer layer 40.

The foregoing outlines features of several embodiments so that thoseskilled in the art may better understand the aspects of the presentdisclosure. Those skilled in the art should appreciate that they mayreadily use the present disclosure as a basis for designing or modifyingother processes and structures for carrying out the same purposes and/orachieving the same advantages of the embodiments introduced herein.Those skilled in the art should also realize that such equivalentconstructions do not depart from the spirit and scope of the presentdisclosure, and that they may make various changes, substitutions andalterations herein without departing from the spirit and scope of thepresent disclosure.

What is claimed is:
 1. A downhole packer assembly, comprising: an innerpacker; and a drain coupled to the inner packer, wherein the draincomprises: a sample inlet; a guard inlet; and a seal disposed betweenthe sample inlet and the guard inlet, wherein the seal is configured tomove into a space between the sample inlet and the guard inlet based onhydrostatic pressure.
 2. The downhole packer assembly of claim 1,wherein the seal is configured to move into the space between the sampleinlet and the guard inlet as a difference between the hydrostaticpressure and a drawdown pressure increases.
 3. The downhole packerassembly of claim 1, wherein the seal is configured to leave the spacebetween the sample inlet and the guard inlet as a difference between thehydrostatic pressure and a drawdown pressure decreases.
 4. The downholepacker assembly of claim 1, wherein the seal is configured to improvesealing performance as the hydrostatic pressure increases.
 5. Thedownhole packer assembly of claim 1, wherein the seal is coupled to asource of fluid at the hydrostatic pressure.
 6. The downhole packerassembly of claim 5, comprising a valve configured to control a flow ofthe fluid at the hydrostatic pressure.
 7. The downhole packer assemblyof claim 5, wherein the seal comprises an inflatable seal configured toinflate with the fluid.
 8. The downhole packer assembly of claim 7,wherein the inflatable seal comprises a first innermost sealing layer, asecond anti-extrusion layer surrounding the first innermost sealinglayer, a third mechanical layer surrounding the second anti-extrusionlayer, and a fourth external skin layer surrounding the third mechanicallayer.
 9. The downhole packer assembly of claim 7, wherein theinflatable seal comprises an inner mechanical layer, an outer mechanicallayer surrounding the inner mechanical layer, and an external skin layersurrounding the outer mechanical layer.
 10. The downhole packer assemblyof claim 9, wherein the external skin layer comprises a shape that isconfigured to fill the space when the inflatable seal is inflated. 11.The downhole packer assembly of claim 5, wherein the seal comprises apiston seal, wherein the piston seal comprises: a piston configured tobe moved into the space by the fluid; and a sealing layer coupled to anexternal surface of the piston and configured to seal against a wall ofa wellbore.
 12. The downhole packer assembly of claim 11, comprising astop configured to block the piston from moving completely out of apiston chamber.
 13. The downhole packer assembly of claim 1, comprisingan outer skin, wherein the inner packer is disposed within the outerskin such that inflation of the inner packer is configured to expand theouter skin.
 14. The downhole packer assembly of claim 1, wherein thedrain comprises a second seal surrounding the guard inlet, wherein thesecond seal is configured to move into a second space surrounding theguard inlet based on hydrostatic pressure.
 15. The downhole packerassembly of claim 10, wherein the downhole packer assembly is configuredfor conveyance within a wellbore by at least one of a wireline or adrillstring.
 16. A method, comprising: providing a packer assemblyhaving an inner packer and a drain coupled to the inner packer, whereinthe drain comprises: a sample inlet; a guard inlet; and a seal disposedbetween the sample inlet and the guard inlet; positioning the packerassembly in a wellbore; inflating the inner packer until the drain isadjacent a wall of the wellbore; moving the seal into a space betweenthe sample inlet and the guard inlet based on hydrostatic pressure;collecting a first formation fluid through the sample inlet; andcollecting a second formation fluid through the guard inlet, wherein theseal blocks mixing of the first and second formation fluids in thespace.
 17. The method of claim 16, comprising moving the seal into thespace between the sample inlet and the guard inlet as a differencebetween the hydrostatic pressure and a drawdown pressure increases. 18.The method of claim 16, comprising improving sealing performance of theseal as the hydrostatic pressure increases.
 19. The method of claim 16,comprising inflating the seal with fluid at the hydrostatic pressure.20. The method of claim 16, comprising moving a piston of the seal withfluid at the hydrostatic pressure.